Hydraulic Turbine Between Middle and Cold Bundles of Natural Gas Liquefaction Heat Exchanger

ABSTRACT

A system and method for liquefying a natural gas stream, including a liquefaction heat exchanger having at least three cooling bundles and arranged such that the natural gas stream passes sequentially therethrough. A first cooling bundle condenses heavy hydrocarbon components in the natural gas stream. A second cooling bundle liquefies the natural gas stream. A third cooling bundle sub-cools the LNG stream. A hydraulic turbine has an inlet operationally connected to an outlet of the second cooling bundle, and an outlet operationally connected to an inlet of the third cooling bundle. The hydraulic turbine cools the LNG stream and reduces the pressure of the LNG stream to form a reduced-pressure LNG stream.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of U.S. Patent Application 62/479,880 filed Mar. 31, 2017 entitled HYDRAULIC TURBINE BETWEEN MIDDLE AND COLD BUNDLES OF NATURAL GAS LIQUEFACTION HEAT EXCHANGER, the entirety of which is incorporated by reference herein.

FIELD

The disclosure relates to the liquefaction of natural gas to form liquefied natural gas (LNG), and more specifically, to improving efficiencies in an LNG-producing heat exchanger.

BACKGROUND

LNG production is a rapidly growing means to supply natural gas from locations with an abundant supply of natural gas to distant markets having a strong demand for natural gas. The conventional LNG cycle includes: a) initial treatments of the natural gas resource to remove contaminants such as water, sulfur compounds and carbon dioxide; b) separating some heavier hydrocarbon gases, such as propane, butane, pentane, etc. by a variety of possible methods including self-refrigeration, external refrigeration, lean oil, etc.; c) refrigerating the natural gas substantially by external refrigeration to form LNG at near atmospheric pressure and about −160° C.; d) transporting the LNG product in ships or tankers designed for this purpose to a market location; e) re-pressurizing and re-gasifying the LNG to form a pressurized natural gas that may distributed in a natural gas distribution system.

The liquefaction of step c) may be accomplished using indirect heat exchange with a refrigerant in a cryogenic heat exchanger. Such a cryogenic heat exchanger may include multiple heat exchange bundles to progressively cool a natural gas stream so the natural gas stream is eventually liquefied and sub-cooled. Traditionally, Joule-Thomson (JT) valves have been used to control pressures and temperatures in the bundles via isenthalpic pressure reduction. While inexpensive, JT valves provide a limited cooling effect and do not recover power from the process stream. What is needed is a method of increasing the cooling effect inside a cryogenic LNG heat exchanger. What is also needed is a method of increasing throughput of an LNG process.

Hydraulic turbines achieve process control objectives (temperature/pressure), reach lower discharge temperatures, and extract power associated with pressure reduction. The thermodynamic basis for a hydraulic turbine (hydraulic expander, expander) is a near-isentropic expansion of a liquid process fluid, through which the temperature of the process fluid is reduced and mechanical shaft work is generated. U.S. Pat. No. 4,334,902 to Paradowski describes a method of sub-cooling a natural gas stream via expansion in the liquid condition, with a hydraulic turbine providing mechanical power possibly for driving a rotary machine. Others have since employed applications of expander technology to refrigeration and liquefaction processes. Design and application of expander technology is generally well understood, and considered standard for latest generation process designs. Typical natural gas liquefaction processes apply hydraulic turbines in the expansion of the final LNG condensate and in the expansion of liquid coolant in the refrigeration cycle. However, the use of hydraulic turbine expanders to expand and cool a process gas stream within an LNG cryogenic heat exchanger has not been suggested.

SUMMARY

The disclosed aspects provide a system for liquefying a natural gas stream. A liquefaction heat exchanger has at least three cooling bundles and is arranged such that the natural gas stream passes sequentially therethrough. A first cooling bundle is configured to condense heavy hydrocarbon components in the natural gas stream. A second cooling bundle is configured to liquefy the natural gas stream. The second cooling bundle has an outlet for passing an LNG stream therethrough. A third cooling bundle has an inlet to receive the LNG. The third cooling bundle is configured to sub-cool the LNG stream. A hydraulic turbine has an inlet operationally connected to the outlet of the second cooling bundle and an outlet operationally connected to the inlet of the third cooling bundle. The hydraulic turbine is configured to cool the LNG stream and reduce a pressure of the LNG stream to form a reduced-pressure LNG stream.

The disclosed aspects also provide a method of liquefying a natural gas stream to produce liquefied natural gas (LNG). The natural gas stream is sequentially cooled in first, second, and third cooling bundles of a liquefaction heat exchanger. The second cooling bundle liquefies the natural gas stream to produce an LNG stream. The LNG stream is cooled and its pressure is reduced between the second cooling bundle and the third cooling bundle using a hydraulic turbine, to thereby produce a reduced-pressure LNG stream. Work energy is produced using the hydraulic turbine.

The disclosed aspects also provide a method of liquefying a natural gas stream to produce liquefied natural gas (LNG). The natural gas stream is sequentially cooled in a liquefaction heat exchanger having first, second, and third cooling bundles. The second cooling bundle liquefies the natural gas stream to produce an LNG stream. The LNG stream is cooled and its pressure is reduced between the second cooling bundle and the third cooling bundle using a hydraulic turbine. Work energy is produced using the hydraulic turbine. Using the work energy, power is generated using a generator connected to the hydraulic turbine. The pressure of the LNG stream exiting the hydraulic turbine is controlled using a control valve disposed between the outlet of the hydraulic turbine and an inlet of the third cooling bundle. The method adjusts at least one of a speed of the hydraulic turbine, an LNG inlet rate of the hydraulic turbine, a position of the control valve, and a speed of the generator, based on at least one of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a schematic diagram of an LNG liquefaction process;

FIG. 2 is a simplified plan view of a main cryogenic LNG heat exchanger according to known principles;

FIG. 3 is a simplified plan view of a main cryogenic LNG heat exchanger according to disclosed aspects;

FIG. 4 is a simplified schematic of a hydraulic turbine according to disclosed aspects;

FIG. 5 is a simplified schematic of a hydraulic turbine according to disclosed aspects;

FIG. 6 is a simplified schematic of a hydraulic turbine according to disclosed aspects;

FIG. 7 is a simplified schematic of a hydraulic turbine according to disclosed aspects;

FIG. 8 is a flowchart of a method according to disclosed aspects; and

FIG. 9 is a flowchart of a method according to disclosed aspects.

DETAILED DESCRIPTION

Various specific aspects and versions of the present disclosure will now be described, including preferred aspects and definitions that are adopted herein. While the following detailed description gives specific preferred aspects, those skilled in the art will appreciate that these aspects are exemplary only, and that the present techniques can be practiced in other ways. Any reference to the “invention” or “aspect” may refer to one or more, but not necessarily all, of the aspects defined by the claims. The use of headings is for purposes of convenience only and does not limit the scope of the present techniques. For purposes of clarity and brevity, similar reference numbers in the several Figures represent similar items, steps, or structures and may not be described in detail in every Figure.

All numerical values within the detailed description and the claims herein are modified by “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art. Certain aspects and features have been described using a set of numerical upper limits and a set of numerical lower limits. It should be appreciated that ranges from any lower limit to any upper limit are contemplated unless otherwise indicated.

The term “gas” is used interchangeably with “vapor,” and means a substance or mixture of substances in the gaseous state as distinguished from the liquid or solid state. Likewise, the term “liquid” means a substance or mixture of substances in the liquid state as distinguished from the gas or solid state. As used herein, “fluid” is a generic term that may include either a gas or liquid.

A “hydrocarbon” is an organic compound that primarily includes the elements hydrogen and carbon although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. As used herein, hydrocarbons generally refer to organic materials, such as any form of natural gas or oil. A “hydrocarbon stream” is a stream enriched in hydrocarbons.

“Pressure” is the force exerted per unit area by the gas on the walls of the volume. Pressure can be shown as pounds per square inch (psi). “Atmospheric pressure” refers to the local pressure of the air. “Absolute pressure” (psia) refers to the sum of the atmospheric pressure (14.7 psia at standard conditions) plus the gauge pressure (psig). “Gauge pressure” (psig) refers to the pressure measured by a gauge, which indicates only the pressure exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig corresponds to an absolute pressure of 14.7 psia).

“Substantial” when used in reference to a quantity or amount of a material, or a specific characteristic thereof, refers to an amount that is sufficient to provide an effect that the material or characteristic was intended to provide. The exact degree of deviation allowable may in some cases depend on the specific context.

“Well” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface.

The term “natural gas” refers to a hydrocarbon gas obtained from a crude oil well (associated gas) or from a subterranean gas-bearing formation (non-associated gas). The composition and pressure of natural gas can vary significantly. A typical natural gas stream contains methane (C₁) as a significant component. Raw natural gas will also typically contain ethane (C₂), higher molecular weight hydrocarbons, one or more acid gases (such as carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon disulfide, and mercaptans), and contaminants such as water, nitrogen, iron sulfide, mercury, helium, wax, and crude oil.

As used herein, the term “compressor” means a machine that increases the pressure of a gas by the application of work. A “compressor” includes any unit, device, or apparatus able to increase the pressure of a gas stream. This includes compressors having a single compression process or step, or compressors having multi-stage compressions or steps, or more particularly multi-stage compressors within a single casing or shell. Gaseous streams to be compressed can be provided to a compressor at different pressures. Some stages or steps of a cooling process may involve two or more compressors in parallel, series, or both. The disclosed aspects are not limited by the type or arrangement or layout of the compressor or compressors, particularly in any refrigerant circuit.

As used herein, the term “JT valve” (also known as Joule-Thomson valve or throttling valve) means a control valve that substantially decreases the pressure of a fluid, including liquids, without the removal of work (approximating an isenthalpic throttling process). Ideally during pressure reduction through a JT valve, the fluid is maintained at constant enthalpy, which in most cases, is accompanied by a temperature reduction. A JT valve is adjustable such that fluid flow rate, pressure or pressure reduction can be controlled.

As used herein, the term “hydraulic turbine” (also known as “liquid expander” or “dense fluid expander”) means a machine that decreases the pressure of a liquid by the removal of work (approximating an isentropic process). Ideally during pressure reduction through a hydraulic turbine, the liquid is maintained at constant entropy, which in most cases, is accompanied by a temperature reduction. For the same pressure reduction, an isentropic process (hydraulic turbine) results in a lower outlet temperature than an isenthalpic process (JT valve). A “hydraulic turbine” includes any unit, device, or apparatus able to decrease the pressure of a liquid stream and extract work. This includes hydraulic turbines having a single pressure reduction process or stage, or hydraulic turbines having multiple stages, or more particularly multi-stage hydraulic turbines within a single casing or shell. Some stages of a depressurization process may involve two or more hydraulic turbines in parallel, series, or both. The disclosed aspects are not limited by the type or arrangement or layout of the hydraulic turbine or hydraulic turbines, particularly in any LNG service.

As used herein, “cooling” broadly refers to lowering and/or dropping a temperature and/or internal energy of a substance by any suitable, desired, or required amount. Cooling may include a temperature drop of at least about 1° C., at least about 5° C., at least about 10° C., at least about 15° C., at least about 25° C., at least about 35° C., or least about 50° C., or at least about 75° C., or at least about 85° C., or at least about 95° C., or at least about 100° C., or at least about 150° C., or at least about 200° C., or at least about 260° C. The cooling may use any suitable heat sink, such as steam generation, hot water heating, cooling water, air, refrigerant, other process streams (integration), and combinations thereof. One or more sources of cooling may be combined and/or cascaded to reach a desired outlet temperature. The cooling step may use a cooling unit with any suitable device and/or equipment. According to some aspects, cooling may include indirect heat exchange, such as with one or more heat exchangers. In the alternative, the cooling may use evaporative (heat of vaporization) cooling and/or direct heat exchange, such as a liquid sprayed directly into a process stream.

A “heat exchanger” broadly means any device capable of transferring heat energy from one medium to another medium, such as between at least two distinct fluids. Heat exchangers include “direct heat exchangers” and “indirect heat exchangers.” Thus, a heat exchanger may be of any suitable design, such as a co-current or counter-current heat exchanger, an indirect heat exchanger (e.g. a spiral wound heat exchanger or a plate-fin heat exchanger such as a brazed aluminum plate fin type), direct contact heat exchanger, shell-and-tube heat exchanger, spiral, hairpin, core, core-and-kettle, printed-circuit, double-pipe or any other type of known heat exchanger. “Heat exchanger” may also refer to any column, tower, unit or other arrangement adapted to allow the passage of one or more streams therethrough, and to affect direct or indirect heat exchange between one or more lines of refrigerant, and one or more feed streams. A heat exchanger as disclosed herein may include multiple heat exchangers as needed or desired.

As used herein, the term “indirect heat exchange” means the bringing of two fluids into heat exchange relation without any physical contact or intermixing of the fluids with each other. Core-in-kettle heat exchangers and brazed aluminum plate-fin heat exchangers are examples of equipment that facilitate indirect heat exchange.

All patents, test procedures, and other documents cited in this application are fully incorporated by reference to the extent such disclosure is not inconsistent with this application and for all jurisdictions in which such incorporation is permitted.

Described herein are methods and systems for liquefying a natural gas stream to form liquefied natural gas (LNG). The described methods and systems use a hydraulic turbine to cool and reduce the pressure of an LNG stream within a liquefaction heat exchanger. The hydraulic turbine may be coupled to an electrical generator or a brake. The brake dissipates the work, extracted from the liquid, to the environment. The electric generator uses the work, extracted from the liquid, to generate electricity. The electricity from an electric generator may be processed by a variable speed constant frequency (VSCF) drive or machine that will allow the speed of hydraulic turbine to be adjustable. The adjustable speed of the hydraulic turbine allows some control over fluid flow rate, pressure or pressure reduction.

Specific aspects of the disclosure include those set forth in the following paragraphs as described with reference to the Figures. While some features are described with particular reference to only one Figure, they may be equally applicable to the other Figures and may be used in combination with the other Figures or the foregoing discussion.

FIG. 1 is a schematic diagram showing the basic steps in a typical natural gas liquefaction process 100. The process 100 is a simplified rendition of a liquefaction process, it being understood that an actual liquefaction process may add, subtract, or replace one or more steps disclosed herein. The feedstock gas 102 to the process 100 comprises mostly light hydrocarbons, and may be a raw feed gas directly transported from one or more wells. Alternatively, the feedstock may be gas from a pipeline that has been partially conditioned to be suitable for such transport. The feedstock gas may contain free liquid, mercury, acid gases, such as carbon dioxide and hydrogen sulfide, water, and other sulfur species. The gas must be treated to remove these contaminants and thoroughly dried before it can be converted to LNG. The process 100 shows typical steps for this treating and dehydration. At block 104 preliminary steps such as liquid removal, pressure control, mercury removal, and metering are performed. At block 106 acid gases such as carbon dioxide and hydrogen sulfide are removed. At block 108 one or more dehydration processes are performed. At this point in process 100 the feedstock gas has been converted to a dry gas stream 110. At block 112 the dry gas stream is pre-cooled to condense heavy hydrocarbons and aromatics, which might freeze in the subsequent liquefaction step. Some liquefied petroleum gases (e.g., ethane, propane, and butane) are also condensed and separated from the heavy hydrocarbons and aromatics in a fractionation unit at block 114. The liquefied petroleum gases 118 are re-injected into the dry gas stream to be liquefied in the liquefaction step at block 116, although some of the liquefied petroleum gases may be drawn off for refrigerant make-up or sold as LPG products. The heavy hydrocarbons and aromatics separated by the fractionation unit 114 form a condensate product 120 that is not liquefied in the liquefaction step.

The liquefaction step at block 116 may be performed by a cryogenic heat exchanger that exchanges heat between the dry gas stream 110 and a refrigerant 122 so that the dry gas stream is liquefied, thereby producing a liquefied natural gas (LNG) stream 124. The refrigerant may include methane, propane, nitrogen, one or more noble gases, and/or one or more fluorocarbons. After liquefying the dry gas stream 110, the refrigerant 122 is refrigerated and compressed at block 126 and recycled back to the liquefaction step at block 116 through a return line 127. At block 128 the LNG is run through a fractionation column or flash drum, where excess nitrogen is rejected, to reduce the nitrogen content of the LNG stream to a desired level. The nitrogen-rich gas stream 130 is typically used as a fuel stream for one or more plant processes. At block 132 the LNG product stream 133, now at near atmospheric pressure, is stored for transport or use.

FIG. 2 is a simplified elevation view of an exemplary known liquefaction heat exchanger 200, which is commonly referred to as a main cryogenic heat exchanger. Liquefaction heat exchanger 200 has three sections of multi-pass heat exchange: a warm bundle 202, a middle bundle 204, and a cold bundle 206. The lines identified by reference numbers 208, 210, and 212 follow the heat exchanger cold passes, which cool all the other passes—termed the warm passes—in the heat exchanger. The liquefaction heat exchanger 200 may be designed as a spiral-wound heat exchanger, in which case the warm passes comprise bundles of small-bore tubing wound around a central mandrel and the cold pass stream is sprayed over the bundles to provide cooling. Alternatively, the liquefaction heat exchanger could be a plate-fin heat exchanger, in which case the warm passes and the cold passes are integrated into a core exchanger separated by alternating plates. Other types of liquefaction heat exchangers may be used as well, but for ease of explaining herein the disclosed aspects, a spiral-wound heat exchanger design will be described.

Referring to FIG. 2, the hydrocarbon gas to be liquefied, which in disclosed aspects may be the dry gas stream 110 shown in FIG. 1, enters the warm bundle 202 where it is pre-cooled to condense heavy components, which might freeze in the colder sections of the liquefaction heat exchanger. The warm bundle is analogous to the precooling step 112 shown in FIG. 1. The pre-cooled natural gas stream 214 leaves the liquefaction heat exchanger so that condensed components such as heavy hydrocarbons may be separated out. After separating out the condensed heavy components, the natural gas stream returns through line 216 and enters the middle bundle 204. The natural gas stream is condensed in the middle bundle and leaves the middle bundle as a high-pressure LNG stream through line 218. A gaseous or two-phase stream of liquefied petroleum gases (LPGs) 220, which may be generated by the fractionation step 114 of FIG. 1, is also passed through the warm bundle 202 and the middle bundle 204 to produce a cooled LPG stream 222. To combine the high pressure LNG stream in line 218 with the cooled LPG stream 222, it is necessary to let-down or reduce the pressure of the high pressure LNG stream. According to known principles, the high-pressure LNG stream in line 218 is let-down or reduced across a Joule-Thomson (J-T) valve 224. The J-T valve 224 operates under pressure control to achieve a suitable downstream pressure to mix with the cooled LPG stream 222. The combined LNG/LPG stream 226 is then sub-cooled as it passes through the cold bundle 206, and leaves the liquefaction heat exchanger as a medium-pressure LNG stream 228.

A light refrigerant stream 230 is cooled successively in the warm bundle 202, the middle bundle 204, and the cold bundle 206, and exits the cold bundle through line 231. The refrigerant in line 231 may pass through a control valve 233, which may be a J-T valve, according to known liquefaction principles, and re-enters the cold bundle via line 208, where it provides cooling for the cold bundle 206. A heavy refrigerant in line 232 is cooled successively in the warm bundle 202 and the middle bundle 204, and exits the middle bundle through line 234. The refrigerant in line 234 may pass through a control valve 241, which may be a J-T valve, according to known liquefaction principles, and re-enters liquefaction heat exchanger 200 via line 210, which is combined with the light refrigerant in line 208. The combined refrigerant then provides further cooling for the middle bundle 204 and the warm bundle 202 before leaving the liquefaction heat exchanger 200 through line 212.

FIG. 3 is a simplified elevation view of a liquefaction heat exchanger 300 according to aspects of the present disclosure. The liquefaction heat exchanger is commonly referred to as a main cryogenic heat exchanger. Liquefaction heat exchanger 300 has three sections of multi-pass heat exchange: a warm bundle 302, a middle bundle 304, and a cold bundle 306. The lines identified by reference numbers 308, 310, and 312 follow the heat exchanger cold passes, which cool all the other passes—termed the warm passes—in the heat exchanger. The liquefaction heat exchanger 300 may be designed as a spiral-wound heat exchanger, in which case the warm passes comprise bundles of small-bore tubing wound around a central mandrel and the cold pass stream is sprayed over the bundles to provide to cooling. Alternatively, the liquefaction heat exchanger could be designed as a plate-fin heat exchanger, in which case the warm passes and the cold passes are integrated into a core exchanger separated by alternating plates. Other types of liquefaction heat exchangers may be used, but for ease of explaining herein the disclosed aspects, a spiral-wound heat exchanger design will be described.

Referring to FIG. 3, the hydrocarbon gas to be liquefied, which in disclosed aspects may be the dry gas stream 110 shown in FIG. 1, enters the warm bundle 302 where it is pre-cooled to condense heavy components, which might freeze in the colder sections of the liquefaction heat exchanger. The warm bundle is analogous to the precooling step 112 shown in FIG. 1. The pre-cooled natural gas stream 314 leaves the liquefaction heat exchanger so that condensed components such as heavy hydrocarbons may be separated out. After separating out the condensed heavy components, the natural gas stream returns through line 316 and enters the middle bundle 304. The natural gas stream is condensed in the middle bundle and leaves the middle bundle as a high-pressure LNG stream through line 318. A gaseous or two-phase stream of liquefied petroleum gases (LPGs) 320, which may be generated by the fractionation step 114 of FIG. 1, is also passed through the warm bundle 302 and the middle bundle 304 to produce a cooled LPG stream 322. To combine the high pressure LNG stream in line 318 with the cooled LPG stream 322, it is necessary to let-down or reduce the pressure of the high pressure LNG stream. According to aspects of the present disclosure, the high-pressure LNG stream in line 318 is passed through a hydraulic turbine 323. While the pressure let-down across a J-T valve is isenthalpic (i.e., no energy removed), pressure let-down across the hydraulic turbine 323 extracts energy in the form of work from the high-pressure LNG stream 318. In so doing, the hydraulic turbine 323 contributes to the process of making the high-pressure LNG stream 318 colder and thereby reduces the cooling duty of the liquefaction heat exchanger 300. As the capacity of the liquefaction heat exchanger 300 is typically limited by the power of its associated refrigeration compression unit, the additional refrigeration contribution from the hydraulic turbine 323 means that a higher LNG production capacity can be achieved by the liquefaction heat exchanger 300, compared to the liquefaction heat exchanger 200 which uses only a J-T valve 224. However, in an aspect, a J-T valve 324 may be disposed to bypass the hydraulic turbine 323. J-T valve 324 provides a back-up function to the hydraulic turbine. The J-T valve 324 may also be used for start-up operation of the liquefaction heat exchanger 300. Additionally, the J-T valve may be used in conjunction with the hydraulic turbine 323 if the flow of the LNG stream in line 318 exceeds the capacity of the hydraulic turbine.

A control valve 325 may be disposed downstream of the hydraulic turbine. The purpose of the pressure control provided by the control valve 325 is to ensure the LNG stream 327 exiting the hydraulic turbine is at a suitable pressure to mix with the cooled LPG stream 322. The control valve 325 may also help to keep the LNG stream in the liquid phase and prevent it from becoming a two-phase stream. The combined LNG/LPG stream 326 is then sub-cooled as it passes through the cold bundle 306, and leaves the liquefaction heat exchanger as a medium-pressure LNG stream 328.

A light refrigerant stream 330 is cooled successively in the warm bundle 302, the middle bundle 304, and the cold bundle 306, and exits the cold bundle through line 331. The refrigerant in line 331 may pass through a control valve 333, which may be a J-T valve, according to known liquefaction principles, and re-enters the cold bundle via line 308, where it provides cooling for the cold bundle 306 through line 308. A heavy refrigerant in line 332 is cooled successively in the warm bundle 302 and the middle bundle 304, and exits the middle bundle through line 334. The refrigerant in line 334 may pass through a control valve 341, which may be a J-T valve, according to known liquefaction principles, and re-enters liquefaction heat exchanger 300 via line 310, which is combined with the light refrigerant in line 308. The combined refrigerant then provides further cooling for the middle bundle 304 and the warm bundle 302 before leaving the liquefaction heat exchanger 300 through line 312.

As previously stated, pressure let-down across the hydraulic turbine 323 extracts energy in the form of work from the high-pressure LNG stream 318. This work may be used to power a generator 340, for example. The generator may provide power to one or more parts of the natural gas liquefaction process 100 or may provide power to other processes, including an external electrical grid. FIG. 4 is a more detailed schematic view of the hydraulic turbine 323 operationally connected to the generator 340. A first set of one or more sensors 402 may be positioned to measure the pressure and/or temperature of the high-pressure LNG stream 318 as it exits the middle bundle 304 (FIG. 3) or as it enters the hydraulic turbine 323. A second set of one or more sensors 404 may be positioned to measure the pressure and/or temperature of the LNG stream 327 downstream of the hydraulic turbine 323. The performance or functionality of various components depicted in FIG. 4 may be adjusted based on the pressures and/or temperatures as sensed by the first and/or second sets of one or more sensors 402, 404, such as the operating speed of the generator 340, the operating speed of the hydraulic turbine 323, the operating position of the control valve 325, the operating position of the J-T valve 324, and/or the rate at which the high-pressure LNG stream 318 is admitted into the hydraulic turbine 323 (through turbine wicket gates 323 a, for example).

FIG. 5 is a schematic view of the hydraulic turbine 323 and generator 340 according to another aspect of the disclosure. A variable-speed constant-frequency (VSCF) drive 350 may be disposed between and operationally connected to the generator 340 and a power system 354, which may comprise an external power grid. The VSCF drive 350 operates to selectively control the generator operating speed based on an operator-defined speed set point. Such action may convert the frequency of electrical output 352 from the generator to match the power system frequency. The generator speed set point in the VSCF drive may be adjusted based on the pressures and/or temperatures as sensed by the first and/or second sets of one or more sensors 402, 404.

It is possible for other components to be operationally connected to the hydraulic turbine 323 in place of or in addition to the generator 340. For example, FIG. 6 is a schematic view of another aspect of the disclosure in which a mechanical brake 360 is operationally connected to the hydraulic turbine 323. The mechanical brake may be adjusted based on the pressures and/or temperatures as sensed by the first and/or second sets of one or more sensors 402, 404. Alternatively or additionally, as shown in FIG. 7, a compressor such as a centrifugal compressor 370 may be operationally connected to the hydraulic turbine via, for example, a shaft 372. The centrifugal compressor 370 may be used to compress one or more fluids in the natural gas liquefaction process 100 or in other processes as desired.

Aspects of the disclosure may be modified in many ways while keeping with the spirit of the disclosure. For example, the generator 340 may also function as a motor to power up the hydraulic turbine 323 during a start-up operation. Additionally, more than one hydraulic turbine may be used in series and/or in parallel with hydraulic turbine 323.

FIG. 8 is a method 800 of liquefying a natural gas stream to produce liquefied natural gas (LNG) according to disclosed aspects. At block 802 the natural gas stream is sequentially cooled in first, second, and third cooling bundles of a liquefaction heat exchanger. The second cooling bundle liquefies the natural gas stream to produce an LNG stream. At block 804 the LNG stream is cooled and its pressure is reduced between the second cooling bundle and the third cooling bundle using a hydraulic turbine, to thereby produce a reduced-pressure LNG stream. At block 806 work energy is produced using the hydraulic turbine.

FIG. 9 is a method 900 of liquefying a natural gas stream to produce liquefied natural gas (LNG). At block 902 the natural gas stream is sequentially cooled in a liquefaction heat exchanger having first, second, and third cooling bundles. The second cooling bundle liquefies the natural gas stream to produce an LNG stream. At block 904 the LNG stream is cooled and its pressure is reduced between the second cooling bundle and the third cooling bundle using a hydraulic turbine. At block 906 work energy is produced using the hydraulic turbine. At block 908, using the work energy, power is generated using a generator connected to the hydraulic turbine. At block 910 the pressure of the LNG stream exiting the hydraulic turbine is controlled using a control valve disposed between the outlet of the hydraulic turbine and an inlet of the third cooling bundle. At block 912 at least one of a speed of the hydraulic turbine, an LNG inlet rate of the hydraulic turbine, a position of the bypass valve, a position of the control valve, and a speed of the generator, are adjusted based on at least one of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.

The aspects disclosed herein provide a method of expanding and cooling a natural gas stream in a liquefaction heat exchanger. This method is applicable in cryogenic heat exchangers used to generate LNG, but may also be used in other cryogenic heat exchangers. The method and system may be retrofitted into an existing LNG producing facility, or may be designed into a new facility. An advantage of the disclosed aspects is that work energy can be extracted from the LNG within a liquefaction heat exchanger. This work energy can be used advantageously in many ways, such as by powering a generator, a mechanical brake, and/or a compressor. Another advantage is that the temperature of the LNG stream is lowered by passing through the hydraulic turbine. This reduces the cooling duty of the liquefaction heat exchanger, and as a result the capacity of the liquefaction heat exchanger can be increased.

Aspects of the disclosure may include any combinations of the methods and systems shown in the following numbered paragraphs. This is not to be considered a complete listing of all possible aspects, as any number of variations can be envisioned from the description above.

-   -   1. A system for liquefying a natural gas stream, comprising:     -   a liquefaction heat exchanger having at least three cooling         bundles and arranged such that the natural gas stream passes         sequentially therethrough, including     -   a first cooling bundle configured to condense heavy hydrocarbon         components in the natural gas stream,     -   a second cooling bundle configured to liquefy the natural gas         stream, the second cooling bundle having an outlet for passing         an LNG stream therethrough, and     -   a third cooling bundle having an inlet to receive the LNG, the         third cooling bundle configured to sub-cool the LNG stream; and     -   a hydraulic turbine having an inlet operationally connected to         the outlet of the second cooling bundle and an outlet         operationally connected to the inlet of the third cooling         bundle, the hydraulic turbine configured to cool the LNG stream         and reduce a pressure of the LNG stream to form a         reduced-pressure LNG stream.

2. The system of paragraph 1, further comprising:

-   -   a first set of one or more sensors situated to sense at least         one of a pressure and a temperature of the LNG stream prior to         entering the hydraulic turbine; and     -   a second set of one or more sensors situated to sense at least         one of a pressure and a temperature of the LNG stream as the LNG         stream exits the hydraulic turbine.     -   3. The system of paragraph 2, wherein at least one of a) a speed         of the hydraulic turbine and b) an LNG inlet flow rate to the         hydraulic turbine is adjusted based on at least one of the         sensed temperature of the LNG stream prior to entering the         hydraulic turbine, the sensed pressure of the LNG stream prior         to entering the hydraulic turbine, the sensed temperature of the         LNG stream as the LNG stream exits the hydraulic turbine, and         the sensed pressure of the LNG stream as the LNG stream exits         the hydraulic turbine.     -   4. The system of paragraph 2, further comprising a bypass valve         operationally connecting the outlet of the second cooling bundle         and the inlet of the third cooling bundle such that, when open,         at least a portion of the LNG stream bypasses the hydraulic         turbine.     -   5. The system of paragraph 4, wherein the bypass valve is         selectively controlled based on at least one of the sensed         temperature of the LNG stream prior to entering the hydraulic         turbine, the sensed pressure of the LNG stream prior to entering         the hydraulic turbine, the sensed temperature of the LNG stream         as the LNG stream exits the hydraulic turbine, and the sensed         pressure of the LNG stream as the LNG stream exits the hydraulic         turbine.     -   6. The system of any of paragraphs 1-5, further comprising a         control valve disposed between the outlet of the hydraulic         turbine and the inlet of the third cooling bundle, wherein the         control valve is selectively controlled based at least in part         on one or more of a sensed temperature of the LNG stream prior         to entering the hydraulic turbine, a sensed pressure of the LNG         stream prior to entering the hydraulic turbine, a sensed         temperature of the LNG stream as the LNG stream exits the         hydraulic turbine, and a sensed pressure of the LNG stream as         the LNG stream exits the hydraulic turbine.     -   7. The system of any of paragraphs 1-6, further comprising a         generator connected to the hydraulic turbine and configured to         generate power based on the work energy generated by the         hydraulic turbine.     -   8. The system of paragraph 7, further comprising:     -   a first set of one or more sensors situated to sense at least         one of a pressure and a temperature of the LNG stream prior to         entering the hydraulic turbine, and     -   a second set of one or more sensors situated to sense at least         one of a pressure and a temperature of the LNG stream as the LNG         stream exits the hydraulic turbine;     -   wherein a speed of the generator is adjusted based on at least         one of the sensed temperature of the LNG stream prior to         entering the hydraulic turbine, the sensed pressure of the LNG         stream prior to entering the hydraulic turbine, the sensed         temperature of the LNG stream as the LNG stream exits the         hydraulic turbine, and the sensed pressure of the LNG stream as         the LNG stream exits the hydraulic turbine.     -   9. The system of paragraph 7, further comprising a         variable-speed constant-frequency (VSCF) drive situated between         the generator and a power system, wherein the VSCF drive is         selectively controlled based at least in part on one or more of         the sensed temperature of the LNG stream prior to entering the         hydraulic turbine, the sensed pressure of the LNG stream prior         to entering the hydraulic turbine, the sensed temperature of the         LNG stream as the LNG stream exits the hydraulic turbine, the         sensed pressure of the LNG stream as the LNG stream exits the         hydraulic turbine and the power system frequency.     -   10. The system of any of paragraphs 1-9, further comprising at         least one of a mechanical brake and a compressor operationally         connected to the hydraulic turbine.     -   11. The system of paragraph 10, wherein the brake is selectively         controlled based at least in part on one or more of a sensed         temperature of the LNG stream prior to entering the hydraulic         turbine, a sensed pressure of the LNG stream prior to entering         the hydraulic turbine, a sensed temperature of the LNG stream as         the LNG stream exits the hydraulic turbine, and a sensed         pressure of the LNG stream as the LNG stream exits the hydraulic         turbine.     -   12. The system of any of paragraphs 1-11, further comprising:     -   a liquefied petroleum gas (LPG) stream configured to pass         through the first cooling bundle and the second cooling bundle,         the reduced-pressure LNG stream being at a pressure so as to be         combined with the LPG stream after the LPG stream has passed         through the second cooling bundle.     -   13. A method of liquefying a natural gas stream to produce         liquefied natural gas (LNG), comprising:     -   sequentially cooling the natural gas stream in first, second,         and third cooling bundles of a liquefaction heat exchanger,         wherein the second cooling bundle liquefies the natural gas         stream to produce an LNG stream;     -   cooling and reducing the pressure of the LNG stream between the         second cooling bundle and the third cooling bundle using a         hydraulic turbine, to thereby produce a reduced-pressure LNG         stream; and     -   producing work energy using the hydraulic turbine.     -   14. The method of paragraph 13, further comprising:     -   adjusting at least one of a) a speed of the hydraulic turbine         and b) an LNG inlet rate of the hydraulic turbine based on at         least one of a sensed temperature of the LNG stream prior to         entering the hydraulic turbine, a sensed pressure of the LNG         stream prior to entering the hydraulic turbine, a sensed         temperature of the LNG stream as the LNG stream exits the         hydraulic turbine, and a sensed pressure of the LNG stream as         the LNG stream exits the hydraulic turbine.     -   15. The method of paragraph 13 or paragraph 14, further         comprising:     -   selectively directing at least a portion of the LNG stream         exiting the hydraulic turbine through a bypass valve that         operationally connects an outlet of the second cooling bundle         and an inlet of the third cooling bundle; and     -   selectively controlling the bypass valve based on at least one         of a sensed temperature of the LNG stream prior to entering the         hydraulic turbine, a sensed pressure of the LNG stream prior to         entering the hydraulic turbine, a sensed temperature of the LNG         stream as the LNG stream exits the hydraulic turbine, and a         sensed pressure of the LNG stream as the LNG stream exits the         hydraulic turbine.     -   16. The method of any of paragraphs 13-15, further comprising         controlling a pressure of the LNG stream exiting the hydraulic         turbine by disposing a control valve between an outlet of the         hydraulic turbine and an inlet of the third cooling bundle,         wherein the control valve is selectively controlled based at         least in part on one or more of a sensed temperature of the LNG         stream prior to entering the hydraulic turbine, a sensed         pressure of the LNG stream prior to entering the hydraulic         turbine, a sensed temperature of the LNG stream as the LNG         stream exits the hydraulic turbine, and a sensed pressure of the         LNG stream as the LNG stream exits the hydraulic turbine.     -   17. The method of any of paragraphs 13-16, further comprising:     -   connecting a generator to the hydraulic turbine; and generating         power using the generator based on the work energy generated by         the hydraulic turbine.     -   18. The method of paragraph 17, further comprising:     -   adjusting a speed of the generator based on at least one of a         sensed temperature of the LNG stream prior to entering the         hydraulic turbine, a sensed pressure of the LNG stream prior to         entering the hydraulic turbine, a sensed temperature of the LNG         stream as the LNG stream exits the hydraulic turbine, and a         sensed pressure of the LNG stream as the LNG stream exits the         hydraulic turbine.     -   19. The method of paragraph 17, further comprising:     -   controlling an electrical output of the generator using a         variable-speed constant-frequency drive situated between the         hydraulic turbine and the generator.     -   20. The method of any of paragraphs 13-19, further comprising:     -   operationally connecting at least one of a mechanical brake and         a compressor to the hydraulic turbine.     -   21. The method of any of paragraphs 13-19, further comprising:     -   obtaining a liquefied petroleum gas (LPG) stream from a         fractionation process that occurs prior to the natural gas         stream being sequentially cooled in the liquefaction heat         exchanger;     -   cooling the LPG stream in the first cooling bundle and the         second cooling bundle, the reduced-pressure LNG stream being at         a pressure so as to be combined with the LPG stream after the         LPG stream has passed through the second cooling bundle.     -   22. The method of paragraph 21, wherein the liquefaction heat         exchanger is part of an operating LNG process, and further         comprising:     -   retrofitting the hydraulic turbine between the second cooling         bundle and the third cooling bundle.     -   23. A method of liquefying a natural gas stream to produce         liquefied natural gas (LNG), comprising:     -   sequentially cooling the natural gas stream in a liquefaction         heat exchanger having first, second, and third cooling bundles,         wherein the second cooling bundle liquefies the natural gas         stream to produce an LNG stream;     -   cooling and reducing the pressure of the LNG stream between the         second cooling bundle and the third cooling bundle using a         hydraulic turbine;     -   producing work energy using the hydraulic turbine;     -   using the work energy, generating power using a generator         connected to the hydraulic turbine;     -   controlling a pressure of the LNG stream exiting the hydraulic         turbine using a control valve disposed between the outlet of the         hydraulic turbine and an inlet of the third cooling bundle; and     -   adjusting at least one of         -   a speed of the hydraulic turbine,         -   an LNG inlet rate of the hydraulic turbine,         -   a position of the control valve, and         -   a speed of the generator, based on at least one of a sensed             temperature of the LNG stream prior to entering the             hydraulic turbine, a sensed pressure of the LNG stream prior             to entering the hydraulic turbine, a sensed temperature of             the LNG stream as the LNG stream exits the hydraulic             turbine, and a sensed pressure of the LNG stream as the LNG             stream exits the hydraulic turbine.     -   24. The method of paragraph 23, further comprising:     -   when the hydraulic turbine is desired to be bypassed,         selectively directing at least a portion of the LNG stream         exiting the middle bundle through a bypass valve that         operationally connects an outlet of the second cooling bundle         and an inlet of the third cooling bundle; and     -   adjusting a position of the bypass valve based on at least one         of the sensed temperature of the LNG stream prior to entering         the hydraulic turbine, the sensed pressure of the LNG stream         prior to entering the hydraulic turbine, the sensed temperature         of the LNG stream as the LNG stream exits the hydraulic turbine,         and the sensed pressure of the LNG stream as the LNG stream         exits the hydraulic turbine.

While the foregoing is directed to aspects of the present disclosure, other and further aspects of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow. 

What is claimed is:
 1. A system for liquefying a natural gas stream, comprising: a liquefaction heat exchanger having at least three cooling bundles and arranged such that the natural gas stream passes sequentially therethrough, including a first cooling bundle configured to condense heavy hydrocarbon components in the natural gas stream, a second cooling bundle configured to liquefy the natural gas stream, the second cooling bundle having an outlet for passing an LNG stream therethrough, and a third cooling bundle having an inlet to receive the LNG, the third cooling bundle configured to sub-cool the LNG stream; and a hydraulic turbine having an inlet operationally connected to the outlet of the second cooling bundle and an outlet operationally connected to the inlet of the third cooling bundle, the hydraulic turbine configured to cool the LNG stream and reduce a pressure of the LNG stream to form a reduced-pressure LNG stream.
 2. The system of claim 1, further comprising: a first set of one or more sensors situated to sense at least one of a pressure and a temperature of the LNG stream prior to entering the hydraulic turbine; and a second set of one or more sensors situated to sense at least one of a pressure and a temperature of the LNG stream as the LNG stream exits the hydraulic turbine.
 3. The system of claim 2, wherein at least one of a) a speed of the hydraulic turbine and b) an LNG inlet flow rate to the hydraulic turbine is adjusted based on at least one of the sensed temperature of the LNG stream prior to entering the hydraulic turbine, the sensed pressure of the LNG stream prior to entering the hydraulic turbine, the sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and the sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 4. The system of claim 2, further comprising a bypass valve operationally connecting the outlet of the second cooling bundle and the inlet of the third cooling bundle such that, when open, at least a portion of the LNG stream bypasses the hydraulic turbine.
 5. The system of claim 4, wherein the bypass valve is selectively controlled based on at least one of the sensed temperature of the LNG stream prior to entering the hydraulic turbine, the sensed pressure of the LNG stream prior to entering the hydraulic turbine, the sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and the sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 6. The system of claim 1, further comprising a control valve disposed between the outlet of the hydraulic turbine and the inlet of the third cooling bundle, wherein the control valve is selectively controlled based at least in part on one or more of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 7. The system of claim 1, further comprising a generator connected to the hydraulic turbine and configured to generate power based on the work energy generated by the hydraulic turbine.
 8. The system of claim 7, further comprising: a first set of one or more sensors situated to sense at least one of a pressure and a temperature of the LNG stream prior to entering the hydraulic turbine, and a second set of one or more sensors situated to sense at least one of a pressure and a temperature of the LNG stream as the LNG stream exits the hydraulic turbine; wherein a speed of the generator is adjusted based on at least one of the sensed temperature of the LNG stream prior to entering the hydraulic turbine, the sensed pressure of the LNG stream prior to entering the hydraulic turbine, the sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and the sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 9. The system of claim 7, further comprising a variable-speed constant-frequency (VSCF) drive situated between the generator and a power system, wherein the VSCF drive is selectively controlled based at least in part on one or more of the sensed temperature of the LNG stream prior to entering the hydraulic turbine, the sensed pressure of the LNG stream prior to entering the hydraulic turbine, the sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, the sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine and the power system frequency.
 10. The system of claim 1, further comprising at least one of a mechanical brake and a compressor operationally connected to the hydraulic turbine.
 11. The system of claim 10, wherein the brake is selectively controlled based at least in part on one or more of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 12. The system of claim 1, further comprising: a liquefied petroleum gas (LPG) stream configured to pass through the first cooling bundle and the second cooling bundle, the reduced-pressure LNG stream being at a pressure so to as to be combined with the LPG stream after the LPG stream has passed through the second cooling bundle.
 13. A method of liquefying a natural gas stream to produce liquefied natural gas (LNG), comprising: sequentially cooling the natural gas stream in first, second, and third cooling bundles of a liquefaction heat exchanger, wherein the second cooling bundle liquefies the natural gas stream to produce an LNG stream; cooling and reducing the pressure of the LNG stream between the second cooling bundle and the third cooling bundle using a hydraulic turbine, to thereby produce a reduced-pressure LNG stream; and producing work energy using the hydraulic turbine.
 14. The method of claim 13, further comprising: adjusting at least one of a) a speed of the hydraulic turbine and b) an LNG inlet rate of the hydraulic turbine based on at least one of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 15. The method of claim 13, further comprising: selectively directing at least a portion of the LNG stream exiting the hydraulic turbine through a bypass valve that operationally connects an outlet of the second cooling bundle and an inlet of the third cooling bundle; and selectively controlling the bypass valve based on at least one of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 16. The method of claim 13, further comprising controlling a pressure of the LNG stream exiting the hydraulic turbine by disposing a control valve between an outlet of the hydraulic turbine and an inlet of the third cooling bundle, wherein the control valve is selectively controlled based at least in part on one or more of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 17. The method of claim 13, further comprising: connecting a generator to the hydraulic turbine; and generating power using the generator based on the work energy generated by the hydraulic turbine.
 18. The method of claim 17, further comprising: adjusting a speed of the generator based on at least one of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 19. The method of claim 17, further comprising: controlling an electrical output of the generator using a variable-speed constant-frequency drive situated between the hydraulic turbine and the generator.
 20. The method of claim 13, further comprising: operationally connecting at least one of a mechanical brake and a compressor to the hydraulic turbine.
 21. The method of claim 13, further comprising: obtaining a liquefied petroleum gas (LPG) stream from a fractionation process that occurs prior to the natural gas stream being sequentially cooled in the liquefaction heat exchanger; cooling the LPG stream in the first cooling bundle and the second cooling bundle, the reduced-pressure LNG stream being at a pressure so as to be combined with the LPG stream after the LPG stream has passed through the second cooling bundle.
 22. The method of claim 21, wherein the liquefaction heat exchanger is part of an operating LNG process, and further comprising: retrofitting the hydraulic turbine between the second cooling bundle and the third cooling bundle.
 23. A method of liquefying a natural gas stream to produce liquefied natural gas (LNG), comprising: sequentially cooling the natural gas stream in a liquefaction heat exchanger having first, second, and third cooling bundles, wherein the second cooling bundle liquefies the natural gas stream to produce an LNG stream; cooling and reducing the pressure of the LNG stream between the second cooling bundle and the third cooling bundle using a hydraulic turbine; producing work energy using the hydraulic turbine; using the work energy, generating power using a generator connected to the hydraulic turbine; controlling a pressure of the LNG stream exiting the hydraulic turbine using a control valve disposed between the outlet of the hydraulic turbine and an inlet of the third cooling bundle; and adjusting at least one of a speed of the hydraulic turbine, an LNG inlet rate of the hydraulic turbine, a position of the control valve, and a speed of the generator, based on at least one of a sensed temperature of the LNG stream prior to entering the hydraulic turbine, a sensed pressure of the LNG stream prior to entering the hydraulic turbine, a sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and a sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine.
 24. The method of claim 23, further comprising: when the hydraulic turbine is desired to be bypassed, selectively directing at least a portion of the LNG stream exiting the middle bundle through a bypass valve that operationally connects an outlet of the second cooling bundle and an inlet of the third cooling bundle; and adjusting a position of the bypass valve based on at least one of the sensed temperature of the LNG stream prior to entering the hydraulic turbine, the sensed pressure of the LNG stream prior to entering the hydraulic turbine, the sensed temperature of the LNG stream as the LNG stream exits the hydraulic turbine, and the sensed pressure of the LNG stream as the LNG stream exits the hydraulic turbine. 